Configurations and methods for acid gas and contaminant removal with near zero emission

ABSTRACT

A gas ( 1 ) comprising hydrogen sulfide, carbon dioxide, and hydrocarbon contaminants is treated in a plant (FIG.  2 ) in a configuration in which waste streams are recycled to extinction. In especially preferred aspects of contemplated methods and configurations, hydrogen sulfide and other sulfurous components are converted to a sulfur product ( 37 ), carbon dioxide ( 44 A) is separated at a purity sufficient for enhanced oil recovery or sale, and hydrocarbon contaminants are purified to a marketable hydrocarbon product ( 49 ).

This application claims the benefit of U.S. provisional patentapplication with the Ser. No. 60/434,358, which was filed Dec. 17, 2002and which is incorporated by reference herein.

FIELD OF THE INVENTION

The field of the invention is gas processing and treating, andespecially gas processing and treating with near zero emissions.

BACKGROUND OF THE INVENTION

Natural gas streams that contain low levels of acid gases and othercontaminants can be economically treated by a wide variety of knowntreating processes. However, with increasing acid gas and othercontaminant content, current treating processes often require relativelylarge quantities of energy and may further require additional processingequipment.

An exemplary known gas treatment configuration that employs the use of aphysical solvent is depicted in prior art FIG. 1 in which an absorber203, a flash drum 205, a recycle compressor 206, exchanger 207, asolvent regenerator 208, a reboiler 209, a solvent pump 216, and arefrigerant chiller 217 are configured to remove hydrogen sulfide andcontaminants from a feed gas (Further components of this plant includesulfur plant 213, hydrogenation and quench unit 214 and tail gas unit215). It should be recognized that such plants are typically notselective in the removal of H₂S and contaminants (i.e., co-absorption ofCO₂ by the solvent is relatively high). Particularly, when the feed gas1 comprises relatively large CO₂ quantities (e.g., greater than 50%),co-absorption of CO₂ in such plants requires higher solvent circulationand higher energy consumption and also produces an acid gas rich in CO₂(typically 80%) that is an undesirable acid gas for the sulfur plants.As a result, and especially where the feed gas comprises relatively highconcentrations of acid gas and other contaminants, the capital andoperating costs required by these processes are generally very high.Very often, post treatment of the treated gas from these units withadditional processing equipment is required, due to the fact thatelimination of contaminants is frequently below desirable levels.

To circumvent at least some of the problems associated with inadequatecontaminant removal, various post treatment methods of treated gaseshave been employed. Unfortunately, most of such methods tend to berelatively inefficient and costly, and where contaminants are removed bya fixed bed absorbent process, they may further pose a disposal problemfor the spent absorbent. Therefore, various problems associated withoperating efficiency, effluents; emissions, and product qualities,particularly in the downstream sulfur recovery unit and tail gas unit,still remain. For example, acid gas produced from such treatingprocesses is generally poor in quality (e.g., comprising significantquantity of contaminants, and/or a relatively large quantity ofco-absorbed CO₂ and hydrocarbons), which often requires additionalprocessing and higher energy consumption, thereby increasing the overallcapital and operating costs of the sulfur plant. Furthermore,co-absorbed hydrocarbons in the acid gas must generally be converted toCO₂ in the sulfur plant, which results in an increase in CO₂ emissionsfrom the process. Thus, despite the significant potential energy valuein the hydrocarbons, most of the currently known processes fail torecover these waste hydrocarbon streams as a valuable product.

In other known processes, a tail gas unit is often used to control thesulfur emissions from the sulfur plant. Even if the emission is reducedto a very low ppm level, the total quantity of annual sulfur emissions(tons/year) in the vent stream is still relatively high, due torelatively large venting rates attributed to the large co-absorbed CO₂in the treating process. Moreover, contaminants and hydrocarbons in theacid gas of most known gas treatment configurations are often notcompletely destroyed in the sulfur plants, and the sulfur product willtherefore be contaminated with unconverted hydrocarbons and mercaptansand will thus become an additional industrial waste disposal problem.

Therefore, while various gas processing treatments and configurationsare known in the art, all or almost all of them suffer from one or moredisadvantages, and especially where the feed gas comprises relativelyhigh levels of acid gases, hydrocarbons and other contaminants.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is an exemplary prior art schematic of a gas treatment plant.

FIG. 2 is an exemplary schematic of a gas treatment plant according tothe inventive subject matter.

SUMMARY OF THE INVENTION

The present invention is directed to plant configurations and methodsfor treatment of a gas comprising relatively high levels of acid gases,hydrocarbons and other contaminants, wherein contemplated configurationsand methods significantly reduce, if not even almost eliminate emissionsof sulfurous components, heavy hydrocarbons, and/or other contaminantswhile providing a sulfur and contaminant-depleted dehydrated gas with alow hydrocarbon dew point suitable for pipeline sales.

In one aspect of the inventive subject matter, a gas treatment plant hasa first absorber in which a lean solvent absorbs carbon dioxide,hydrogen sulfide, and heavy hydrocarbons. A second absorber is fluidlycoupled to the first absorber, wherein at least part of the hydrogensulfide is separated from the carbon dioxide, and a sulfur plantreceives the hydrogen sulfide to produce a sulfur product and a tailgas, wherein at least part of the tail gas is hydrogenated and isrecycled to the absorber.

Particularly contemplated plant configurations further include aregenerator coupled to the first and second absorbers, wherein theregenerator produces an acid gas, and wherein at least part of thehydrocarbon is separated from the acid gas as a hydrocarbon liquid.Where the hydrocarbon liquid is sold as a valuable product, a strippermay be included that receives at least part of the hydrocarbon liquidand in which residual sulfurous compounds are at least partiallystripped from the hydrocarbon liquid, with the stripped vapor optionallyfed to a sulfur plant. With respect to the carbon dioxide in the acidgas, it is generally preferred that the second absorber is operated at alower pressure and at a higher temperature than the first absorber suchthat carbon dioxide is desorbed from the rich solvent and is recycledback to the first absorber. The so obtained carbon dioxide may then beoptionally used for enhanced oil recovery or used as commercial product.

In one aspect of the inventive subject matter, a gas treatment plant hasan absorber that receives (a) a feed gas comprising carbon dioxide andhydrogen sulfide, (b) a carbon dioxide saturated lean solvent, and (c)that produces an overhead vapor comprising at least a portion of thecarbon dioxide, wherein a lean solvent is combined with the overheadvapor and then cooled, to form a cooled carbon dioxide saturated leansolvent, thereby reducing the temperature rise in the absorber and henceincreasing selective absorption of the hydrogen sulfide from the feedgas in producing a treated gas with 4 ppm or less total sulfide content.

The absorber produces in especially preferred configurations a bottomproduct that is further reduced in pressure and heated to a highertemperature sufficient to desorb the carbon dioxide content from thebottom product, and the H₂S content in the so separated carbon dioxideis re-absorbed in a second absorber using a portion of the carbondioxide saturated lean solvent.

In yet another aspect of the inventive subject matter, a gas treatmentplant has a solvent regenerator that receives from a plurality ofabsorbers a rich solvent comprising an acid gas and a heavy hydrocarbon,and that produces an overhead vapor that is further cooled andseparated, thereby forming an acid gas, water and liquid hydrocarbon.The hydrocarbon liquid is optionally fed to a stripper that fractionatesthe hydrocarbon liquid to produce a hydrogen sulfide depletedhydrocarbon product and a vapor comprising hydrogen sulfide that is fedto a sulfur plant.

In a particularly preferred aspect of such configurations, the acid gas,containing residual quantities of contaminants (heavy hydrocarbons andmercaptans), is fed to an absorber in which a carbon dioxide depletedhydrogen sulfide rich solvent is used to further scrub the acid gas andto produce a concentrated H₂S stream depleted of heavy hydrocarbons,which is preferably fed to the sulfur plant. It is still furthercontemplated that the sulfur plant produces a marketable sulfur productand a tail gas, wherein at least part of the tail gas is hydrogenatedand is recycled to at least one of the plurality of the absorbers.

In a further aspect of the inventive subject matter, a gas treatmentplant has an absorber that receives from a solvent regenerator a vaporcomprising hydrogen sulfide and a hydrocarbon, and that further receivesa carbon dioxide-depleted solvent comprising hydrogen sulfide, whereinthe absorber produces a hydrocarbon-depleted overhead vapor comprisinghydrogen sulfide that is fed to a sulfur plant, and ahydrocarbon-enriched bottom product that is recycled to the solventregenerator. It is generally preferred in such configurations that thecarbon dioxide-depleted solvent is produced by another absorber thatseparates hydrogen sulfide from carbon dioxide using a carbon dioxidesaturated lean solvent, and that a portion of the carbondioxide-depleted solvent is fed to the solvent regenerator.

Consequently, the inventors contemplate a method of treating a gas inwhich in one step the gas is optionally contacted with a first portionof a lean solvent to absorb at least one of a heavy hydrocarbon and aheavy mercaptans (ethyl mercaptans and heavier mercaptans) from the gasinto the first portion of the lean solvent. In another step, the gas iscooled and the cooled gas is contacted in an absorber with a secondportion of the lean solvent to absorb at least one of a lighthydrocarbon, a light mercaptans (methyl mercaptans), and H₂S into thesecond portion of the lean solvent, wherein the second portion of thelean solvent is saturated with carbon dioxide. In yet another step, thegas exiting the absorber is further contacted with a third portion ofthe lean solvent to saturate the third portion with carbon dioxidethereby forming a gas solvent mix, and the gas solvent mix is thencooled and separated thereby forming the second portion of the leansolvent that is saturated with carbon dioxide.

Various objects, features, aspects and advantages of the presentinvention will become more apparent from the following detaileddescription of preferred embodiments of the invention.

DETAILED DESCRIPTION

The inventors discovered that gas comprising relatively high levels ofacid gases and other contaminants can be treated in a process thatsignificantly reduces, if not even almost eliminates emissions ofsulfurous components, hydrocarbons, and/or other contaminants.Contemplated process will typically produce a dehydrated gas with a lowhydrocarbon dewpoint that will meet pipeline sales gas specifications.

Furthermore, contemplated configurations will produce a hydrogen sulfiderich and hydrocarbon depleted gas that can be efficiently processed in asulfur plant, and the tail gas of the sulfur plant is (afterhydrogenation and quenching) recycled back to the feed gas. Stillfurther, the hydrocarbons separated and recovered from the feed gas incontemplated configurations are generally suitable for use as a liquidfuel after further processing. Thus, it should be especially appreciatedthat contemplated configurations and methods allow for feed gasprocessing of a contaminated feed gas in which all undesirablecomponents (especially including heavy and light hydrocarbons,mercaptans, hydrogen sulfide, and carbon dioxide) are recycled toextinction, or removed and recovered as commercially valuable products.

In particularly preferred configurations and methods, a four-stepabsorption process is employed in which a lean solvent (most preferablya solvent comprising dialkyl ethers of polyethylene glycols and water)selectively absorbs sulfurous components, hydrocarbons, and/or othercontaminants. Additionally or optionally, a cooling/absorption processmay be included to trap undesirable hydrocarbons and contaminants (e.g.,mercaptans or disulfides) in a hydrocarbon liquid that is then processedin another step to produce valuable products.

An exemplary configuration is depicted in FIG. 2. Here, feed gas stream1, at ambient temperature and atmospheric pressure, is combined with thehydrogenation/quench gas stream 2 to form stream 3 that is compressed infeed compressor 101. Recycle stream 4 from the reboiled absorber 110 isfed to the interstage of compressor 101 and the total gas stream iscompressed to a suitable pressure forming stream 5, typically at 200 to400 psig, or as needed for the pipeline requirement.

It should generally be appreciated that the feed gas composition mayvary considerably, and that suitable feed gases include natural gas atvarious pressures, synthesis gas, landfill waste gases, and variousrefinery off-gases. However, in especially preferred aspects, the feedgas is a low pressure, low quality natural gas with a composition ofabout 30 to 70% CO₂, 20 to 50% C₁; 2 to 5% H₂S, 0.5 to 10% H₂, 3 to 5%C₂-C₅, 0.5 to 2% C₆-C₇, 0.1 to 0.5% C₈-C₉₊, 0.2 to 1% mercaptans,disulfides, COS and HCN contaminants, with the balance being inerts(e.g., N₂). Moreover, it should be recognized that suitable feed gasesmay comprise water, and may even be saturated with water.

In an exemplary operation, the low quality feed gas stream has a feedrate of 100 MMscfd and is supplied at close to atmospheric pressure andambient temperature, and is saturated with water. In the exemplaryconfiguration of FIG. 2, the four absorption steps are performed withlean solvent streams using lean solvent stream 6, 14, 25, and 45respectively. With respect to the solvent employed in contemplatedabsorbers (absorber 103, 110 and 118), it should be recognized thatnumerous physical solvents and mixtures thereof are appropriate. Thereare numerous physical solvents known in the art, and exemplary solventsinclude propylene carbonate, tributyl phosphate, normalmethylpyrrolidone, and other various polyethylene glycol dialkyl ethers.Alternatively, suitable solvents may also include an enhanced tertiaryamine or other solvent having similar behavior as a physical solvent.However, it is generally preferred that the solvent comprises a mixtureof dimethyl ethers of polyethylene glycols and water. Furthermore, itshould be appreciated that water at suitable concentrations in dimethylethers of polyethylene glycols will promote stripping and desorption ofcontaminants from the solvent.

In a first absorption step, a specified and relatively small quantity ofthe lean solven is injected to the feed gas to trap heavy components,including C₉₊ hydrocarbons and heavy mercaptans before the feed gas isfurther cooled and enters the absorber. Removal of the heavycontaminants from this first absorption prevents significant quantitiesof heavy hydrocarbons and contaminants from entering the secondabsorption step, thereby avoiding downstream heavy hydrocarboncondensation in the absorber. Furthermore, excessive heavy hydrocarbonsin the absorber tends to cause foaming, which is also undesirable. Thequantity of lean solvent required in this first absorption step isrelative small, and will generally depend on the amount of heavyhydrocarbons in the feed. However, in most configurations, the quantityof lean solvent will be less than 10% of the total circulating solvent,and more typically about 2% to 5% of total solvent circulation.Furthermore, it should be recognized that the quantity of lean solventcan be adjusted as needed to remove the heavy hydrocarbons.

In the exemplary configuration of FIG. 2, lean solvent stream 6, atabout 20 gpm, is mixed with compressed feed gas stream 5 forming stream7 that is cooled in exchanger 102 with treated gas stream 18 (theproduct gas), to cooled stream 8 at typically 60° F. to 90° F. It shouldbe especially noted that the absorption efficiency is significantlyenhanced with the chilling process in exchanger 102 resulting insubstantially complete removal of heavy components (e.g., C₉₊hydrocarbons), heavy mercaptans, and disulfides, as well as the majority(i.e., at least 75%, and more typically at least 90%) of water content.Exchanger 102 preferably uses the refrigeration content in the treatedgas stream 18, thus requiring no external cooling and producing warmedproduct gas 46. However, it should be recognized that optional and/oradditional external refrigeration may also be included (e.g., where thefeed gas contains relatively large amounts of heavy components).

It is generally preferred that the absorber 103 comprises two sections,wherein the lower section is employed for separating the heavycontaminants from the feed gas absorbed in the first step, while theupper section is employed for the second absorption step to removelighter contaminants (e.g., hydrogen sulfide, light mercaptans, lighthydrocarbons). In such configurations, the heavy contaminants (e.g.,hydrocarbons, mercaptans, disulfides, etc.) are fed into and separatedin the lower section of absorber 103 and removed via solvent stream 10that is further fractionated in regenerator 113. Removal of the heavycontaminants in a lower section of the absorber is especiallyadvantageous as subsequent absorption steps in the upper section(typically the second and third absorption steps) operate at lowertemperatures that may promote hydrocarbon condensation and foaming ofthe heavy contaminants (supra). However, in alternative configurations,stream 10 can be separately processed in a regenerator (not shown)operating under vacuum pressure that may be required for fractionationand removal of the very heavy components.

Where the absorber has an upper and a lower section, it is generallypreferred that the two sections are separated, most typically by achimney tray 125. Therefore, flashed gas stream 9 will flow upwards fromthe lower section of the absorber through chimney tray 125 and entersthe upper section of the column. There, the gas is brought intocounter-current contact with a carbon dioxide saturated solvent stream11 entering near the top of the absorber. The absorber typicallycomprises conventional trays or packing, which provides approximately 14to 18 equilibrium stages of gas-liquid contact. Under these conditions,approximately 1000 to 1200 gpm of lean solvent circulation are requiredto reduce the total sulfur content (H₂S, mercaptans and disulfides) ofthe natural gas to less than 4 ppmv. However, and depending on theparticular gas composition and volume, it should be recognized that thetype of absorber and the number of equilibrium stages may varyconsiderably.

It should be especially recognized that the use of a cold carbon dioxidesaturated solvent is particularly advantageous as the contacting stagesin absorber 103 are almost exclusively utilized for selective absorptionof hydrogen sulfide and contaminants since the solvent is alreadypreloaded with carbon dioxide. Since the quantity of hydrogen sulfide,in the feed gas is relatively small compared to carbon dioxide, theabsorption of hydrogen sulfide results in a smaller temperature rise inthe absorber. With the absorber operating at a lower temperature, theoverall solvent circulation and energy consumption can be reduced. Withsuch selective absorption process, acid gas going to the sulfur plantwill generally contain less carbon dioxide and is more concentrated inhydrogen sulfide. The terms “carbon dioxide saturated solvent” and“solvent saturated with carbon dioxide” are used interchangeably hereinand refer to a solvent that is saturated with at least 50%, moretypically at least 80%, and most typically at least 90% carbon dioxideat a particular pressure and temperature as compared to 100% saturationwith carbon dioxide at the particular pressure and temperature. Thus,the term “selective absorption of hydrogen sulfide” as used hereinrefers to a preferred absorption of hydrogen sulfide over absorption ofcarbon dioxide from a particular gas into a particular solvent.

Another important advantage of such an absorption process is that allcontaminants are concentrated in the vapor phase 32 of regeneratoroverhead 29, resulting in a higher partial pressure of thesecontaminants, which allows for condensation and hence removal of thesecontaminants. A still further advantage of such processes is that acidgas from the regenerator will contain less carbon dioxide and lesshydrocarbons, which means that a downstream sulfur plant will requireless fuel gas and oxygen in the production of a high-quality sulfur.Consequently, the equipment size of such a sulfur plant is smaller andtherefore reduces capital and operating cost of the sulfur plant. Theterm “sulfur plant” as used herein generally refers to all plantconfigurations in which hydrogen sulfide is converted to elementalsulfur (and other by products), and which will typically emit a tail gascomprising relatively low levels of sulfurous compounds.

The absorber 103 produces an overhead stream 12, which is partiallydepleted of contaminants (i.e., contains less contaminants than thestream entering the absorber), typically at 20 to 40° F., and a richsolvent stream 13 from chimney tray 125, typically at 40 to 60° F. Theoverhead stream 12 is mixed with a lean solvent 14 supplied from thesolvent chiller 121 at 0 to 40° F., at approximately 1100 to 1300 gpm,forming the vapor-solvent mixture of stream 15.

It should be especially appreciated that this additional step ofvapor-solvent contact will saturate the lean solvent stream 14 withcarbon dioxide while removing the residual, contaminants and sulfurcompounds from the feed gas in overhead stream 12. Stream 15 is furthercooled in exchanger 104 using external refrigeration that removes theheat of absorption generated by the absorption of carbon dioxide by thesolvent, and the mixture is further chilled to typically 10 to 40° F.forming stream 16. Consequently, it should be recognized that the lowtemperature of stream 16 will favor the vapor-solvent absorptionequilibrium, which in turn will result in a higher loading of acid gasand contaminants in the solvent, thereby reducing the overall solventcirculation and energy consumption.

It should be especially recognized that without this coolingarrangement, the absorber overhead temperature will be higher than thatof the lean solvent, as limited by the approach to equilibriumtemperature in the absorber. As solvent loading capacity is reduced atthe higher temperature, a higher solvent circulation is necessary tomeet the same product gas sulfur specification. Higher solvent flow isundesirable, as co-absorption of carbon dioxide will increase,consequently increasing the quantity of acid gases that needs to beprocessed in the sulfur plant.

The chilled vapor solvent mixture of stream 16 is separated in separator105 into a contaminant depleted vapor stream 18 (the clean product gas)and a carbon dioxide enriched liquid stream 17. Stream 17 is split intotwo streams, where about 25% is sent as stream 25 to the thirdabsorption, step in absorber 110, while the remaining 75%, as stream 43,is pumped using solvent pump 106 to the top of absorber 103 as stream 11to contact the contaminated natural gas rising up the absorber. Therefrigerant content of vapor stream 18, typically at 10 to 40° F., isused to cool the feed gas stream 7 in exchanger 102. The treated gasexits the treating unit as stream 46 as the product gas.

The contaminant laden solvent stream 13 is letdown in pressure in JTvalve 107 to form stream 19, typically at 100 to 200 psig. Stream 19 isthen heated in exchanger 108 by lean solvent stream 28, to typically 240to 275° F., forming stream 20. Under these high temperature and lowerpressure conditions, most of the acid gas, and particularly carbondioxide is desorbed. Stream 20 is separated in separator 109 into avapor stream 24 and a flashed liquid stream 21. About 98% or more of thelight hydrocarbons; such as methane, about 95% of carbon dioxide, andabout 70% of the hydrogen sulfide are desorbed in stream 24. The flashedliquid stream 21 containing the residual gas (mainly hydrogen sulfideand contaminants) is mixed with streams 10 and 50 to form stream 22prior to being sent to regenerator 113 via JT valve 112 for furtherfractionation.

The third absorption step is performed in a reboiled absorber 110 thatconcentrates hydrogen sulfide and contaminants in the rich solvent byrejecting its carbon dioxide content (e.g., by heating the richsolvent). The use of reboiler 111 is optional and is required only toproduce an acid gas with a very high hydrogen sulfide concentration.Stream 24 enters near the bottom of reboiled, absorber 110 and leansolvent stream 25, supplied from separator 105 in the second absorptionstep, enters near the top of the column. When supplementary heating dutyis required at reboiler, either hot oil or steam can be used as a heatsource to maintain the desired bottom temperature. Typically, the thirdabsorption step is used to reject over 95% of the carbon dioxide contentof stream 24. The reboiled absorber 110 is typically designed with 8 to12 equilibrium stages of vapor solvent contact. Conventional trays orpacking can be used as the vapor solvent contact device. The requiredsolvent rate of stream 25 is typically at 25% of the total circulationor as needed to reabsorb substantially all of the hydrogen sulfide andcontaminants that are desorbed in stream 24 via heating by exchanger108. The absorber overhead vapor stream 44, containing mostly carbondioxide and methane and depleted of hydrogen sulfide and contaminantscan be used for carbon dioxide production in stream 44A, and/or recycledback to the interstage of the feed compressor in stream 4. The recyclingprocess maximizes the recovery of methane (typically greater than 98%,and more typically greater than 99.5%) and other valuable gases whileeliminating a potential source of emission.

The reboiled absorber overhead vapor 44 is a highly concentrated carbondioxide stream that is substantially contaminant free (typically lessthan 0.1 vol %, more typically less than 0.05 vol %), and is suitablefor use as a feedstock for chemical production (e.g., for ureafertilizer manufacturing, or soft drink industries). The residualcontaminants level in this stream is very low and therefore, furtherpurification to meet the product carbon dioxide specification requiresminimal capital and operating costs. Alternatively, the highlyconcentrated carbon dioxide stream may be, employed in enhanced oilrecovery in the associated oil field production. It should still furtherbe recognized that removal of the carbon dioxide rich stream 44A alsoreduces the recycle flow of stream 4 and further improves the heatingvalue of the product gas (particularly when the product gas is requiredto meet the heating value or Wobbe Index specification of a sales gas).

The reboiled absorber bottom stream 23, containing about 5% of theresidual carbon dioxide is split into stream 45 and stream 50. Stream 45is used as hydrogen sulfide-rich lean solvent (after reduction inpressure via JT valve 128) for absorption of hydrocarbons in the fourthabsorption step in absorber 118. Stream 50 is combined with stream 21from separator 109 and stream 10 from the first absorption step, formingstream 22. Stream 22 is letdown in pressure via valve 112 to about 25psig forming stream 26 and enters the top section of regenerator 113.Regenerator 113 is preferably a fractionation column, typically designedwith 12 to 16 equilibrium stages of vapor solvent contact. Conventionaltrays or packing can be used as the vapor solvent contact device. Theregenerator bottoms temperature is typically maintained at 285 to 300°F. with application of heat with either a hot oil or steam as a heatsource. The reboiler duty is about 30 to 40 MMBtu/h, or as required toproduce a lean solvent with very low sulfur and mercaptans content (lessthan 5 ppm) necessary for meeting the 4 ppmv total sulfur specificationfor sales gas.

The regenerator produces a lean solvent stream 28 and all overhead gasstream 29. The heat content of lean solvent is recovered by preheating(partially regenerating) the rich solvent in exchanger 108. In exchanger108, stream 28 is cooled to form stream 40 at typically 100 to 120° F.The cooled solvent is further pumped to absorber pressure with pump 120.The pump discharge stream 41 is split into stream 6 and stream 42.Stream 6 is injected to the feed gas stream for heavy hydrocarbon andcontaminant removal in the first absorption step. Stream 42 is cooledwith refrigeration in exchanger 121 to typically 0 to 40° F., and ismixed with overhead vapor 12 from absorber 103 in the second absorptionstep.

It should be especially appreciated that the presence of a large amountof water (steam) at the bottom of the regenerator will enhance strippingand removal of the heavy components. Therefore, a person of ordinaryskill in the art will adjust the water content in the solvent (e.g.,dimethyl ethers of polyethylene glycols) to promote and/or optimizestripping and desorption of the contaminants from the solvent. Inaddition to removal of contaminants in the regenerator, the leanersolvent is very effective in contaminant absorption in the secondabsorption step to help meet the stringent product gas specification.

The regenerator overhead gas stream 29 is cooled with a cooling medium(e.g., cooling water followed by a refrigerant) in exchanger 115 totypically 40 to 50° F., forming stream 30 that is further separated in athree phase separator 116 into a liquid stream 31, a vapor stream 32, awater stream 34 and a hydrocarbon stream 35. Liquid stream 31, typicallycomprising water saturated with solvent, hydrocarbons and contaminant ispumped by reflux pump 117 to the regenerator as stream 27. A portion ofthe water is delivered to the regenerator to maintain the water contentof the solvent at a predetermined level. As those skilled in the artwill readily recognize, various feed gas streams occasionally includeundesirable amounts of water. Accordingly, to maintain the water contentof the solvent at a predetermined concentration, any additional waterabsorbed by the solvent from the feed gas can be removed in regenerator113 as stream 34.

The contaminants in stream 32 decrease with decreasing temperature, andthe lower limit is governed by the water freeze out temperature of 32°F. The residual contaminant level, and in particular the lightercontaminants such as methyl mercaptans, benzene, toluene and xylene maystill be present in significant quantity (even at about 40° F., thecontaminants level can be as high as 1 to 2%). The presence of such highlevels of contaminants will have negative impacts in the sulfuroperation plant, and particularly includes high energy consumption andshort catalyst life, and off specification sulfur product.

To circumvent such problems, a fourth absorption step using absorber 118is used to further treat the acid gas stream 32. Lean solvent stream 46Aemployed in this step originates from the bottom of absorber 110 in thethird absorption step via stream 45. This solvent stream is particularlyadvantageous in the absorption of residual contaminants since it issaturated with hydrogen sulfide. Use of solvent 46A will reject most ofthe hydrogen sulfide from the solvent to the overhead stream 47 whileabsorbing most of the hydrocarbons and contaminants from the acid gas instream 32. This fourth absorption step further improves the hydrogensulfide concentration to the sulfur plant by as high as 10%. Theconcentration of hydrogen sulfide in stream 47 to the sulfur plant canbe as high as 70%. The bottom stream 33 from absorber 118 is pumped bypump 119 as stream 36 to the upper section of the regenerator 113, whichseparates the contaminants and hydrocarbon liquid in the overhead drum116 producing the raw hydrocarbon liquid stream 35.

Thus, in contemplated configurations it is expected that over 99% of thecontaminants (heavy hydrocarbons and mercaptans) are removed in stream35. Since this stream is saturated with light hydrocarbons and lightmercaptans, further stripping is typically required before it can besold as a hydrocarbon product. Therefore a stripper 126 with heatsupplied by reboiler 127 is used to strip these light components fromstream 35. Preferred strippers contain contacting trays that are used tofractionate the lighter components from the heavy liquid producing aliquid product 49. The overhead vapor stream 48 containing the lightmercaptans and H₂S is sent to sulfur plant for conversion as a sulfurproduct.

Water stream 34, containing minimal residual contaminants, is purgedfrom separator 116 to the sour water stripper unit in order to maintain,a water balance. Vapor streams 47 and 48 from absorber 118 and stripper126, respectively, typically comprising 50 to 70% hydrogen sulfide, 30to 50% carbon dioxide (and very low level residual hydrocarbon content)can be fed directly to a sulfur plant 122. Such gas composition isexpected to allow the sulfur plant to operate in a stable and efficientmode, with minimum oxygen and fuel consumption, while convertingvirtually all the residual hydrocarbons and mercaptans and disulfidesinto inert products. The sulfur plane produces a sulfur product stream37 and a tail gas stream 38. The tail gas stream 38, predominantlycomprising carbon dioxide and small quantity of sulfur oxides, is sentto a hydrogenation and quench unit 123. The gas is hydrogenated over acatalyst bed that converts all sulfur oxides back to hydrogen sulfide.The converted gas is quenched with water, cooled and exits the quenchgas unit as stream 39.

It should be especially appreciated that conventional processes normallyrequire a tail gas unit that includes another treatment unit and anincineration unit. Besides added capital and operating costs,conventional processes also generate a source of gaseous emission. Astighter controls on overall sulfur emissions are imposed by regulations,emissions from a tail gas unit will no longer meet the regulationrequirements. In contrast, contemplated configurations eliminate suchemissions entirely. Furthermore, a small blower 124 can be used(optionally depending on the feed pressure) to recycle the tail gas backto the plant inlet.

Consequently, it should be recognized that contemplated configurationsallow for economically treating a highly contaminated feed gas to meetpipeline specification, improved contaminant removal, reduced recycleflow rates, heating and cooling duties, and significantly reducedcapital and operating costs associated with the use of such a process.Particularly, carbon dioxide content in the product gas can be tailoredto meet the sales gas specification by diverting the carbon dioxide richrecycle stream to outside the unit for industrial usages.

Furthermore, it should be recognized that in contemplated configurationsand methods a low quality gas is treated in four absorption steps forremoval of contaminants, including heavy hydrocarbons, mercaptans,disulfides and aromatics; and that a cooler/stripper step process isemployed in the solvent regenerator to remove the contaminants in aliquid, which is stripped to produce a stabilized marketable liquidproduct.

It should also be especially noted that in contemplated configurationsthe hydrogen sulfide is concentrated in the fourth absorption step toproduce an acid gas with a hydrogen sulfide content of greater that 60%.Such concentrated hydrogen sulfide streams may advantageously beconverted to an inert form of sulfur. It should be particularlyappreciated that the contaminant depleted acid gas stream is a highlydesirable feed gas to a sulfur plant as the contaminant depleted acidgas stream will avoid poisoning and deactivation of the catalyst in aClaus reactor in the sulfur plant and thus ensure an on-specificationsulfur product.

While contemplated configurations and processes are particularly usefulfor selectively removing gas contaminants such as hydrogen sulfide,mercaptans, disulfides, aromatics and heavy hydrocarbons from naturalgas, synthesis gas, landfill waste gas, or refinery off-gases, it shouldbe recognizes that alternative contaminants, including various sulfurcompounds, carbonyl sulfide, cyanides, and other gas contaminants mayalso be removed from a variety of feed gases. Still further, andparticularly when the feed gas contains a significant carbon dioxidecontent, contemplated configurations and processes can also be used toefficiently extract carbon dioxide to meet sales gas specification onthe heating value and Wobbe Index. The extracted carbon dioxide, whichis highly concentrated and contaminant free, may be further purified andused for chemical production or enhanced oil recovery.

Additional advantages of contemplated configurations and methods includerecycling of the tail gas from a sulfur plant after hydrogenation andquenching. The so converted tail gas (mostly hydrogen sulfide andcarbon-dioxide) is recycled back to the suction of the feed gascompressor. Furthermore, off-gas from the third absorption step is alsorecycled back to the interstage of the feed gas compressor. Thus, insuch recycling to extinction configurations all or almost all emissionsources generated in the process are eliminated.

Contemplated configurations and processes can be advantageously used toprocess and treat a contaminant waste gas stream while upgrading the lowquality gas to a high quality dehydrated gas for a consumer pipeline. Atthe same time, contemplated configurations and processes will recoverthe energy value of the hydrocarbon contents as a sellable hydrocarbonliquid and a sulfur product. Therefore, such configurations andprocesses recycle all or almost all of the waste gas streams and willgenerally not produce gaseous emissions that are normally encountered incurrently known processing facilities.

Therefore, the inventors contemplate a gas treatment plant with a firstabsorber in which a lean solvent absorbs carbon-dioxide, hydrogensulfide, and a hydrocarbon. A second absorber fluidly coupled to thefirst absorber, wherein at least part of the hydrogen sulfide isseparated from the carbon dioxide, and sulfur plant receives thehydrogen sulfide to produce a sulfur product and a tail gas, wherein atleast part of the tail gas is hydrogenated and is recycled to theabsorber. Such plants may advantageously include a regenerator that isfluidly coupled to the first and second absorber, wherein theregenerator produces an acid gas, and wherein at least part of thehydrocarbon is separated from the acid gas as a hydrocarbon liquid. Astripper may be included that receives at least part of the hydrocarbonliquid and in which residual sulfurous compounds are at least partiallystripped from the hydrocarbon liquid (and are preferably fed to thesulfur plant). In particularly preferred configurations, the secondabsorber is operated at a lower pressure and at a higher temperaturethan the first absorber such that the carbon dioxide is desorbed formthe rich solvent and is recycled back to the first absorber. The soproduced carbon dioxide may then be used for enhanced oil recovery orused as commercial product (after optional further purification).

Viewed from another perspective, contemplated plants may include anabsorber that receives (a) a feed gas comprising carbon dioxide andhydrogen sulfide and (b) a carbon dioxide saturated lean solvent, andthat produces an overhead vapor comprising at least a portion of thecarbon dioxide, wherein a lean solvent is combined with the overheadvapor and then cooled, to form a cooled carbon dioxide saturated leansolvent, thereby reducing the temperature rise in the absorber and henceincreasing selective absorption of the hydrogen sulfide from the feedgas in the lean solvent. Such absorbers will preferably produce a bottomproduct that is reduced in pressure and heated to a (higher) temperaturesufficient to desorb the carbon dioxide content from the bottom product,and it is further preferred that the hydrogen sulfide content in theseparated carbon dioxide is further re-absorbed in a second absorberusing a portion of the carbon dioxide saturated lean solvent.

Furthermore, the inventors contemplate that a gas treatment plantaccording to the inventive subject matter may include a solventregenerator that receives from a plurality of absorbers a solventcomprising an acid gas and a hydrocarbon, and that produces an overheadvapor that is further cooled and separated forming an acid gas, waterand hydrocarbon liquid. The hydrocarbon liquid is optionally fed to astripper that fractionates the hydrocarbon liquid to produce a hydrogensulfide depleted hydrocarbon product and a vapor comprising hydrogensulfide that is fed to a sulfur plant. In such configurations, it isgenerally preferred that the acid gas is fed to an absorber in which acarbon dioxide depleted hydrogen sulfide rich solvent scrubs the acidgas, wherein the scrubbed acid gas is fed to the sulfur plant (which mayproduce a tail gas, wherein at least part of the tail gas ishydrogenated and recycled to at least one of the plurality of theabsorbers).

Viewed from yet another perspective, contemplated plants may include anabsorber that receives from a solvent regenerator a vapor comprisinghydrogen sulfide and a hydrocarbon, wherein the absorber furtherreceives a carbon dioxide-depleted solvent comprising hydrogen sulfide,and wherein the absorber produces a hydrocarbon-depleted overhead vaporcomprising hydrogen sulfide that is fed to a sulfur plant, and ahydrocarbon-enriched bottom product that is recycled to the solventregenerator. It is generally preferred that in such configurations thecarbon dioxide-depleted solvent is produced by another absorber thatseparates hydrogen sulfide from carbon dioxide using a carbon dioxidesaturated lean solvent, and that a portion of the carbondioxide-depleted solvent is fed to the solvent regenerator.

Consequently, the inventors contemplate a method of treating a gas inwhich in one step the gas is optionally contacted with a first portionof a lean solvent to absorb at least one of a heavy hydrocarbon and aheavy mercaptan from the gas into the first portion of the lean solvent.In another step, the gas is cooled and the cooled gas is contacted in anabsorber with a second portion of the lean solvent to absorb at leastone of a light hydrocarbon, a light mercaptan, and H₂S into the secondportion of the lean solvent, wherein the second portion of the leansolvent is saturated with carbon dioxide. In yet another step, the gasexiting the absorber is further contacted with a third portion of thelean solvent to saturate the third portion with carbon dioxide therebyforming a gas solvent mix, and the gas solvent mix is then cooled andseparated thereby forming, the second portion of the lean solvent thatis saturated with carbon dioxide.

Thus, specific embodiments and applications of near-zero emission gastreating processes have been disclosed. It should be apparent, however,to those skilled in the art that many more modifications besides thosealready described are possible without departing from the inventiveconcepts herein. The inventive subject matter, therefore, is not to berestricted except in the spirit of the disclosure. Moreover, ininterpreting both the specification, all terms should be interpreted inthe broadest possible manner consistent with the context. In particular,the terms “comprises” and “comprising” should be interpreted asreferring to elements, components, or steps in a non-exclusive manner,indicating that the referenced elements, components, or steps may bepresent, or utilized, or combined with other elements, components, orsteps that are not expressly referenced.

1. A gas treatment plant comprising: a first absorber in which a leansolvent absorbs carbon dioxide, hydrogen sulfide, and a hydrocarbon; asecond absorber fluidly coupled to the first absorber in which at leastpart of the hydrogen sulfide is separated from the carbon dioxide; asulfur plant that receives the at least part of the hydrogen sulfide toproduce a sulfur product and a tail gas, wherein at least part of thetail gas is hydrogenated and is recycled to the absorber; and aregenerator that is fluidly coupled to the first and second absorber,wherein the regenerator produces an acid gas, and wherein at least partof the hydrocarbon is separated from the acid gas as a hydrocarbonliquid.
 2. The gas treatment plant of claim 1 further comprising a thirdabsorber that receives at least part of the hydrocarbon liquid and inwhich residual sulfurous compounds are at least partially removed fromthe hydrocarbon liquid.
 3. The gas treatment plant of claim 2 whereinthe residual sulfurous compounds are fed to a sulfur plant.
 4. The gastreatment plant of claim 1 wherein the second absorber is operated at alower pressure and at a higher temperature than the first absorber suchthat that the carbon dioxide desorbed from the solvent in the secondabsorber has a purity of at least 90 mol %.
 5. The gas treatment plantof claim 4 wherein the carbon dioxide is used for enhanced oil recoveryor used as commercial product.
 6. A gas treatment plant comprising: anabsorber that is configured to receive (a) a feed gas comprising carbondioxide and hydrogen sulfide, (b) a carbon dioxide saturated leansolvent, and (c) wherein the absorber is further configured to producean overhead vapor comprising at least a portion of the carbon dioxide; aconduit fluidly coupled to the absorber and configured to allowcombination of a lean solvent with the overhead vapor to so allowformation of the carbon dioxide saturated lean solvent, and a coolerconfigured to allow cooling of the carbon dioxide saturated lean solventto thereby allow for increased selective absorption of the hydrogensulfide from the feed gas in the lean solvent.
 7. The gas treatmentplant of claim 6 wherein the absorber produces a bottom product that isreduced in pressure and heated to a temperature sufficient to desorb thecarbon dioxide from the bottom product.
 8. The gas treatment plant ofclaim 7 wherein at least a portion of the hydrogen sulfide in thedesorbed carbon dioxide is absorbed in a second absorber using a portionof the carbon dioxide saturated lean solvent.
 9. A gas treatment plantcomprising: a solvent regenerator that receives from a plurality ofabsorbers a solvent comprising an acid gas and a hydrocarbon, and thatproduces an overhead vapor; a separator that receives the overhead vaporand separates the acid gas from the hydrocarbon to form a hydrocarbonliquid; and a stripper that is fluidly coupled to the separator andfractionates the hydrocarbon liquid to produce a hydrogen sulfidedepleted hydrocarbon product and a vapor comprising hydrogen sulfidethat is fed to a sulfur plant.
 10. The gas treatment plant of claim 9wherein the acid gas is fed to an absorber in which a carbon dioxidedepleted hydrogen sulfide rich solvent scrubs the acid gas.
 11. The gastreatment plant of claim 10 wherein the scrubbed acid gas is fed to thesulfur plant.
 12. The gas treatment plant of claim 11 wherein the sulfurplant produces a tail gas, and wherein at least part of the tail gas ishydrogenated and is recycled to at least one of the plurality of theabsorbers.
 13. A gas treatment plant comprising: an absorber thatreceives from a solvent regenerator a vapor that comprises hydrogensulfide and a hydrocarbon, and that further receives a carbondioxide-depleted solvent comprising hydrogen sulfide; and wherein theabsorber produces a hydrocarbon-depleted overhead vapor comprisinghydrogen sulfide that is fed to a sulfur plant, and ahydrocarbon-enriched bottom product that is recycled to the solventregenerator.
 14. The gas treatment plant of claim 13 wherein the carbondioxide-depleted solvent is produced by another absorber that separateshydrogen sulfide from carbon dioxide using a carbon dioxide saturatedlean solvent.
 15. The gas treatment plant of claim 13 wherein a portionof the carbon dioxide-depleted solvent is fed to the solventregenerator.
 16. A method of treating a gas comprising: optionallycontacting a gas with a first portion of a lean solvent to absorb atleast one of a heavy hydrocarbon and a heavy mercaptan from the gas intothe first portion of the lean solvent; cooling the gas and contactingthe cooled gas in an absorber with a second portion of the lean solventto absorb at least one of a light hydrocarbon, a light mercaptan, andH2S into the second portion of the lean solvent, wherein the secondportion of the lean solvent is saturated with carbon dioxide; contactingthe gas exiting the absorber with a third portion of the lean solvent tosaturate the third portion with carbon dioxide thereby forming a gassolvent mix; and cooling and separating the gas solvent mix, therebyforming the second portion of the lean solvent that is saturated withcarbon dioxide.
 17. The method of claim 16 wherein the step ofoptionally contacting is performed before the gas enters the absorber,and wherein the contacted gas is cooled before the contacted gas entersthe absorber.
 18. The method of claim 16 wherein part of the secondportion of the lean solvent that is saturated with carbon dioxide isemployed in another absorber as an absorbing solvent that removeshydrogen sulfide from a vapor.
 19. The method of claim 18 wherein theanother absorber is operated under conditions to reject carbon dioxidefrom the part of the second portion of the lean solvent.